CHENIERE ENERGY, INC - CORPORATE PRESENTATION January 2016 - Cheniere Energy: LNG
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CHENIERE ENERGY, INC. CORPORATE PRESENTATION January 2016
Forward Looking Statements
This presentation contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference herein are “forward-looking statements.” Included among “forward-
looking statements” are, among other things:
statements regarding the ability of Cheniere Energy Partners, L.P. to pay distributions to its unitholders or Cheniere Energy Partners LP Holdings, LLC to pay dividends to its shareholders;
statements regarding Cheniere Energy Inc.’s, Cheniere Energy Partners LP Holdings, LLC’s or Cheniere Energy Partners, L.P.’s expected receipt of cash distributions from their respective subsidiaries;
statements that Cheniere Energy Partners, L.P. expects to commence or complete construction of its proposed liquefied natural gas (“LNG”) terminals, liquefaction facilities, pipeline facilities or other
projects, or any expansions thereof, by certain dates or at all;
statements that Cheniere Energy, Inc. expects to commence or complete construction of its proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects by certain dates or at all;
statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries
worldwide, or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure, or demand for and prices related to natural gas, LNG or other
hydrocarbon products;
statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
statements relating to the construction of our proposed liquefaction facilities and natural gas liquefaction trains (“Trains”) and the construction of the Corpus Christi Pipeline, including statements
concerning the engagement of any engineering, procurement and construction ("EPC") contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other
contractor, and anticipated costs related thereto;
statements regarding any agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements
regarding the amounts of total LNG regasification, liquefaction or storage capacities that are, or may become, subject to contracts;
statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
statements regarding our planned development and construction of additional Trains, including the financing of such Trains;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections or objectives, including anticipated revenues, capital expenditures,
maintenance and operating costs, EBITDA, project EBITDA, project cash flow, distributable cash flow, deconsolidated cash flow, pre-tax cash flow and pre-tax cash flow per share, any or all of which are
subject to change;
statements regarding projections of revenues, expenses, earnings or losses, working capital or other financial items;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
statements regarding our anticipated LNG and natural gas marketing activities; and
any other statements that relate to non-historical or future information.
These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “contemplate,” “develop,” “estimate,” “example,” “expect,” “forecast,” “goals,”
“opportunities,” “plan,” “potential,” “project,” “propose,” “subject to,” “strategy,” “target,” and similar terms and phrases, or by use of future tense. Although we believe that the expectations reflected in these forward-
looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements,
which speak only as of the date of this presentation. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in
“Risk Factors” in the Cheniere Energy, Inc., Cheniere Energy Partners, L.P. and Cheniere Energy Partners LP Holdings, LLC Annual Reports on Form 10-K filed with the SEC on February 20, 2015, which are
incorporated by reference into this presentation. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these ”Risk Factors.” These forward-looking
statements are made as of the date of this presentation, and other than as required under the securities laws, we undertake no obligation to publicly update or revise any forward-looking statements.
2
Cheniere LNG Platform Underway
31.5 mtpa ~87% Cash flows from
currently under LNG volumes contracted fixed fees -
construction not tied to
20-year contracts with commodity prices
fixed fees, no price
7 trains, design capacity reopeners, and parent as Long term SPAs support debt
of 4.5 mtpa each counterparty or guarantor service coverage
~$30B ~$4.3B Flexible, Scalable,
capital spend Industry-leading
annual fixed fees platform
Stable cash flows
Significant investment in underpinned by investment
U.S. infrastructure grade counterparties
3
Executing on Strategy
Complete construction on 7 LNG trains on an accelerated basis, on time and on budget
Transition to an operating company, first cargo expected from Sabine Pass late February/March 2016
Continue commercialization of additional LNG trains and excess LNG volumes
Seek additional growth initiatives with emphasis on accretive projects and optimization of shareholder
returns
4
Cheniere Projected Cash Flow Build-Up With 7 Trains
CQP CCL CEI Standalone
($ in billions, except per share amounts) (SPL T1-5/ SPLNG/CTPL) CCL T1-2
Project EBITDA to CEI (net of minority interests) $1.0* $1.3 $2.3
Plus: Management fees to CEI 0.1
Less: CEI G&A (0.3)
CEI Standalone EBITDA $2.1
Less: CCL project interest expense (0.5)
Less: CEI-level interest expense (0.0)
Pre-tax CEI cash flow $1.6
Pre-tax CEI cash flow per share $5.8(1)
Pre-tax CEI cash flow per share (no CMI sales) $4.2(1)
Estimates based on fixed fees underpinned by 20-year SPAs representing ~87% of capacity
Remaining capacity estimated to be sold based on prevailing market spreads
* Represents expected cash flows from ownership in CQP and CQH, net of interest expense
Note: See “Forward Looking Statements” Slide. For supplementary financial details, see slide 26.
Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds and remaining equity requirements funded by operating cash flow and cash on hand.
Scenario which includes CMI sales assumes market spreads of ~$2.50 as of December 2015.
EBITDA, project EBITDA, pre-tax cash flow and pre-tax cash flow per share are non-GAAP measures. EBITDA is computed as earnings before interest, taxes, depreciation and amortization. We have not made any forecast of net income,
which would be the most comparable financial measure under GAAP, and we are unable to reconcile differences between these forecasted non-GAAP measures and net income. Non-GAAP measures have limitations as an analytical
tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and should be evaluated only on a supplementary basis.
(1) Assumes ~277 million CEI shares outstanding – assumes conversion of $1.0 billion PIK Convertible Notes due 2021 and $1.0 billion Senior Secured Convertible Notes due 2025 at $93.64/share.
5
Maintenance & Operating Cost Estimates
Maintenance Buildup for SPL (T1-5) and CCL (T1-2) Combined Estimated Annualized Amount
($ in mm, includes escalation averaged over 20 years) (Cash basis)
Ongoing labor expense $ 40
GE contract(1) and other general maintenance contracts 150
Spare parts 30
Other vendor contracts / maintenance support 20
Capital maintenance budget 30
Total estimated annualized cash costs $270
Total as % of EPC capital costs ~1.5%
Amounts above include all expected maintenance costs for SPL and CCL on a combined basis (operating
and capex) averaged over 20 years; estimated costs are ~1.5% of the total EPC costs of the trains
(industry norm)
GE covers highest risk components; turbines and compressor wear parts replaced every 6 years; SPL
contract in place, CCL contract expected to be signed in 2016
GE guarantees equipment performance and provides 24/7 monitoring services
Property and equipment covered by comprehensive insurance to mitigate risk of expense due to damage,
failure, natural disaster, etc.
These expense estimates have been reviewed by the Lenders’ independent engineer
Cheniere staff at SPL includes LNG industry experience of 47 professionals from 20 operating
liquefaction terminals worldwide: ~600 years of liquefaction experience on site
(1) Estimate includes base cost, performance incentives, and escalation to 2020.
6
Cheniere Summary Organization
Cheniere Energy, Inc.
Public (NYSE MKT: LNG)
19.9%
80.1% Interest 100% Interest 100% Interest 100% Interest 100% Interest
Cheniere Energy Partners LP Cheniere Corpus Christi
Holdings, LLC Cheniere Energy Marketing, LLC Liquefaction, LLC Other Project
Partners GP, LLC (“CMI”) (“CCL”) Developments
(NYSE MKT: CQH)
• Int’l LNG marketing • Liquefaction facilities
55.9% Interest (1)
2.0% Interest & Incentive • SPAs with SPL and CCL • 9 mtpa under construction
Dist. Rights • LNG vessel charters • 4.5 mtpa under
Cheniere Energy Partners, L.P. development
(NYSE MKT: CQP) • 10.1 Bcf of storage
Blackstone (BX) 29.0% (1)
• 2 berths
Public 13.1% (1)
100% Interest
Sabine Pass LNG, L.P. Sabine Pass Cheniere Creole Trail
(“SPLNG”) Liquefaction, LLC Pipeline, L.P.
(“SPL”) (“CTPL”)
• Regasification facilities • Liquefaction facilities • 1.5 Bcf/d capacity for SPL
• 4.0 Bcf/d of capacity • 22.5 mtpa under construction • Provides gas supply for SPL
• 17.0 Bcf of storage • 4.5 mtpa under development
• 2 berths
Note: This organizational chart is provided for illustrative purposes only, is not and does not purport to be a complete organizational chart of Cheniere.
(1) Blackstone’s reported ownership interest is based solely on ownership of Class B units. As Class B units accrete Blackstone will increase its ownership percentage, and the public and CQH will have reduced ownership
percentages.
7
Cheniere’s Key Businesses
Unmatched scale and first-mover advantage provide industry-leading platform for further asset
integration
LNG Platform
Developing/constructing LNG terminals located along Gulf of Mexico
7 Trains, 31.5 mtpa under construction; 2 Trains, 9.0 mtpa permitted, ready for commercialization
Scalable platform
SPL T1-5 and CCL T1-2 underpinned by long-term contracts with investment grade counterparties or
parent guarantor
Gas Procurement
Providing feedstock for LNG production
Redundant pipeline capacity ensures reliable gas deliverability
Upstream pipeline capacity provides access to diverse supply sources
Cheniere Marketing
LNG sales provided to customers on a short, mid, and long-term basis
Up to 9 mtpa LNG volumes expected from SPL T1-6 and CCL T1-3
LNG offered DES or FOB, tied to indices such as Henry Hub, TTF and NBP
LNG vessels chartered for DES sales
8Cheniere LNG Platform Along Gulf Coast
Sabine Pass Liquefaction Project
6 train development – 27 mtpa
(~3.8 Bcf/d in export capacity)
Trains 1-5 are under construction
First LNG cargo expected late
February/March 2016
Corpus Christi LNG Terminal
5 train development – 22.5 mtpa
(~3.2 Bcf/d in export capacity)
Trains 1-2 are under construction
First LNG expected in late 2018
9Aerial View of SPL Construction – December 2015
Train 6 Under Development
Train 5
T5 Soil Stabilization
T1 Methane Cold Box
Train 3 T1 Ethylene Cold Box
Air Coolers
Propane Condenser Area
Train 1
Train 4
Train 2
T3-4 Gas Meter
T1-2 Gas Meter
10Aerial View of CCL Construction – December 2015
Tank C Tank B
Under Development Tank A
T1 Foundation
Train 1
Train 2
Train 3
Under Development
11Cheniere LNG Projects: Attractive Features
Cheniere LNG SPAs: LNG price tied to Henry Hub, offer destination flexibility, upstream gas procurement
services, no lifting requirements
SPAs with investment grade off-takers featuring parent as counterparty or guarantor & pricing with HH +
fixed fee (no price reopeners)
EPC contractor: proven track record of execution; proven liquefaction technology
Sabine Pass Customers
BG Gulf Coast LNG Gas Natural Fenosa Korea Gas Corporation GAIL (India) Limited Total Gas & Power N.A. Centrica plc
Corpus Christi Customers
PT Pertamina Gas Natural Woodside Energy Électricité de EDP Energias de
(Persero) Endesa S.A. Iberdrola S.A. Fenosa Trading France Portugal S.A.
12Forecast Cheniere LNG Portfolio Summary
SPL CCL SPL CCL
(in MTPA)
(in MTPA) Trains 1-5 Trains 1-2
Total
Train 6 Train 3
Total
Design Capacity 22.5 9.0 31.5 4.5 4.5 40.5
Under Construction 22.5 9.0 31.5 - - 31.5
LT SPAs sold to date 19.8 7.7 27.4
- 1.5(1) 28.8
(% sold) (~88% sold) (~86% sold) (~87% sold)
Excess Volumes/CMI 2.7 1.3 4.1 TBD TBD TBD
Trains under construction underpinned by long term SPAs
Continuing commercialization of additional trains; FID expected upon, among other things, obtaining
sufficient long term SPAs to underpin financing required and obtaining financing (permits already
obtained)
(1) Includes ~0.7 mtpa contract with CMI for Central El Campesino in Chile.
13CEI Standalone EBITDA Forecast with Additional Trains
Illustrative cash flow build-up ($ in billions)
Run-rate scenarios
7 trains 8 trains 9 trains
SPL T1-5/6 and SPLNG via GP/IDR and CQH $1.0* $1.0* $1.3*
Management fees $0.1 $0.1 $0.1
CCL T1-2/3 $1.3 $2.0 $2.0
CMI profit share - - -
Total $2.4 $3.1 $3.3
Less CEI G&A ($0.3) ($0.3) ($0.3)
CEI Standalone EBITDA $2.1 $2.8 $3.0
Estimated EBITDA for CEI standalone based on addition of Train 8 (Corpus Christi Train 3) and Train 9
(Sabine Pass Train 6)
* Represents expected cash flows from ownership in CQP and CQH, net of interest expense.
Note: See “Forward Looking Statements” Slide. For supplementary financial details, see slide 26
Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds and remaining equity requirements funded by operating cash flow and cash on hand.
Scenario assumes full utilization of capacity available and excess volumes sold by CMI at prevailing market spreads of ~$2.50/mmbtu as of December 2015.
8 train case assumes additional ~2.1MTPA of 20-year SPAs at $3.50/mmbtu on CCL Train 3; 9 train case assumes 1.5MTPA of 20-year SPAs at $3.50/mmbtu on SPL Train 6.
EBITDA is a non-GAAP measure. EBITDA is computed as earnings before interest, taxes, depreciation and amortization. We have not made any forecast of net income, which would be the most comparable financial measure under GAAP, and we
are unable to reconcile differences between forecasted EBITDA and net income. Non-GAAP measures have limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and
should be evaluated only on a supplementary basis.
14Gas Procurement: Sabine Pass Terminal
Securing feedstock for LNG
production with balanced portfolio
approach
To date, have entered into term gas
supply contracts with producers under
1-7 year contracts aggregating
approximately 2 Tcf.
Supply contracts cover ~50% of the
required daily load for Trains 1-4 at
Sabine Pass
Pricing averages HH - $0.10 discount
Redundant pipeline capacity helps
ensure reliable gas deliverability
Secured firm pipeline transportation
capacity of approximately ~4.2 Bcf/d
of deliverability into Sabine Pass, or
~160% of the total load for Trains 1-4
Upstream pipeline capacity provides
access to diverse supply sources
High degree of visibility into our ability
to consistently deliver gas to Sabine
Pass on a variable basis at Henry
Hub flat
15Gas Procurement: Corpus Christi Terminal
CCL contracted long-term direct and upstream
pipeline transport capacity for Trains 1 and 2
– Tennessee P/L: 0.3 Bcf/d
– KM Tejas P/L: 0.25 Bcf/d
Marcellus /
– NGPL P/L: 0.385 Bcf/d Utica
– Transco P/L: 0.4 Bcf/d
Negotiating with producers for term gas supply NGPL
Tennessee Gas
HPL
KM Tejas
Oasis
Enterprise
Woodford
Granite
Wash
Haynesville
Permian Barnett
Basin
Eagle Ford
Corpus Christi
Shale Plays
Basins
16Cheniere Marketing
Platform for LNG sales - short, mid, long-term sales, FOB or DES basis
Scale for up to 9 mtpa including
LNG purchases from Cheniere London, U.K.
terminals and other places
SPAs with SPL and CCL for all LNG Washington, D.C.
volumes not sold to 3rd parties
~560 million MMBtu sold to date to
investment-grade counterparties, 1- Houston, TX Singapore
5 yr. terms, prices linked to HH or
European indices such as TTF, NBP
~150 million MMBtu at HH + fixed fee
~410 million MMBtu into Europe Santiago, Chile
Chartered LNG vessels for DES
sales
Developing complementary,
high-value markets through
Chartered LNG Vessels SPA with SPL SPAs with CCL
small-scale asset investments
Professional staff based in London,
Houston, Washington, Santiago, and
Singapore
17LNG Market Prices Profitable for Cheniere Cheniere can profitably sell LNG given lower prices Market price sensitivity Europe LNG Sale Price ($/MMBtu) $5.00 $6.00 $7.00 $8.00 Implied margin $1.00 $2.00 $3.00 $4.00 Asia LNG Sale Price ($/MMBtu) $7.00 $8.00 $9.00 $10.00 Implied margin $2.00 $3.00 $4.00 $5.00 As shown in sensitivity table above, Cheniere can profitably sell LNG into key demand centers even in periods of lower market prices If LNG prices remain at lower levels, we would expect global LNG demand to increase, thus signaling the need for more liquefaction projects Cheniere positioned as a low-cost supplier Assumes Henry Hub price of $3.00/MMBtu, shipping cost to Europe of $0.50/MMBtu and shipping cost to Asia of $1.50/MMBtu. 18
Growth Projects
Leverage core competencies – platform for future growth projects
~$6B in near term major growth projects focused on expansions of liquefaction capacity
Growth Project Estimated Unlevered Costs
Corpus Christi Train 3 ~$3B(1)
Sabine Pass Train 6 ~$2.5B
Total Growth Projects ready for commercialization ~$5.5B
Estimated Combined Unlevered cost per ton ~$610
Assessing additional project opportunities to drive future growth
Permitting process initiated for Corpus Christi Trains 4 & 5
Domestic gas pipeline infrastructure opportunities
International infrastructure investments for projects where Cheniere would be the LNG supplier
(1) Based on current EPC contract.
19Projected Global LNG Demand by 2025
Demand expected to increase 193 mtpa to 436 mtpa by 2025, a 6% CAGR
Average of 23 mtpa new liquefaction capacity needed each year(1)
Europe
31 78 92
2015 2020 2025
Asia
305
Americas 260
184
22 19 23
Middle East/N. Africa
2015 2020 2025
2015 2020 2025 10 17
6
2015 2020 2025
Source: Wood Mackenzie
Q3 2015 LNG Tool
(1) Assumes 85% utilization of nameplate capacity
20U.S. to Be One of Top Three LNG Suppliers
Projected Liquefaction Capacity
94
mtpa
~50
mtpa
64 77 81
mtpa 68 mtpa
under 31.5 mtpa mtpa
1.4 const. mtpa
mtpa under 26
const. mtpa
2014 2025 2025 2014 2025 2014 2025
United States Cheniere AP AP
Qatar Australia
Sabine Pass T1-6
Corpus Christi T1-5
MEG MEG
Rest of World
Includes Existing and
AB AB Under Construction
Projects
2014: 171 mtpa
2025: 189 mtpa
2014 2025
Source: Wood Mackenzie Q3 2015, Cheniere research 2014 Global LNG Liquefaction Capacity: ~37 Bcf/d
21Cheniere Competitive Advantage: Low Cost
The U.S. is one of the lowest cost natural gas providers in the world
U.S. liquefaction project costs are also significantly lower due to less project development needed
Breakeven LNG price for Cheniere LNG export facilities is one of the lowest compared to other proposed
LNG projects
Estimated breakeven LNG pricing range, Delivered Ex-Ship to Asia
$20
$16.70
$14.70
LNG prices ($/MMBtu)
$15
$13.60
$13.20
$10.20 $11.80 $11.90
$10
$11.20
$8.50
$8.80
$8.40
$7.50
$5
Cheniere Gulf Coast West Africa Southeast Asia East Africa Western Canada Northwest Australia
Source: Cheniere Research, Wood Mackenzie, company filings and investor materials.
Note: Breakeven prices derived assuming unlevered after-tax returns of 10% on all other projects over construction plus 20 years of operation at 90% utilization. Henry Hub at $3.00/MMBtu
22In Summary Primary focus on completing construction of 7 LNG trains on an accelerated basis, on time and on budget 2 additional trains fully permitted and ready for commercialization – Cheniere positioned to grow as low-cost provider to market with projected growing demand Cheniere volumes remain profitable in key LNG demand centers despite broad weakness in commodity markets Leverage core competencies to develop additional projects with emphasis on accretive projects and optimization of shareholder returns 23
CHENIERE ENERGY, INC. APPENDIX
Cheniere’s Debt Summary – January 2016
($ in millions)
Cheniere Energy, Inc. Convertible Debt
$1,000 PIK Convertible Notes due 2021 (4.875%)
(NYSE MKT: LNG) $625 Convertible Notes due 2045 (4.250%)
Cheniere Energy Partners Trains 1-2 Equity
CQP GP Cheniere Marketing, LLC Cheniere CCH $1,000 Senior Secured
LP Holdings, LLC (& IDRs) (CMI) Holdco II, LLC Convertible Notes due
(NYSE MKT: CQH) 2025
Cheniere Corpus Christi Trains 1-2 Debt
Cheniere Energy Partners, Holdings, LLC ~$8,400 Credit Facility due
L.P. (NYSE MKT: CQP) (CCH) 20223
Sabine Pass Corpus Christi
Sabine Pass LNG, L.P. Creole Trail Pipeline Liquefaction, LLC
Liquefaction, LLC
(SPLNG) (CTPL) (CCL)
(SPL)
Sr Secured Notes $400 Term Loan due 2017 (L+325) Trains 1-5 Debt Pertamina SPA (79.4 Tbtu / yr)
$1,666 due 2016 (7.50%) $4,600 Credit Facilities due 20201 Endesa SPA (117.3 Tbtu / yr)
$420 due 2020 (6.50%) $2,000 Notes due 2021 (5.625%)
$1,000 Notes due 2022 (6.250%) Iberdrola SPA (39.7 Tbtu / yr)
Total TUA (1 Bcf/d) SPL Firm Transport (1.5 Bcf/d) $1,500 Notes due 2023 (5.625%) Gas Natural (78.2 Tbtu / yr)
$2,000 Notes due 2024 (5.750%)
$2,000 Notes due 2025 (5.625%) Woodside (44.1 Tbtu / yr)
Chevron TUA (1 Bcf/d)
$1,200 Working Capital Facility EDF (40.0 Tbtu / yr)
due 20202
SPL TUA (2 Bcf/d) EDP (40.0 Tbtu / yr)
BG SPA (286.5 Tbtu / yr)
CMI SPA
(1) Includes $2,850 million term loan facility, $1,150 million Republic of Korea (“ROK”) covered facility
Gas Natural SPA (182.5 Tbtu / yr)
and $600 million ROK direct facility. Interest on the term loan facility is L+175 bps during construction
and operation. Under the ROK credit facilities, interest includes L+175 on the direct portion and L+130 KOGAS SPA (182.5 Tbtu / yr)
on the covered portion during construction and operation. In addition, SPL will pay 45 bps for
insurance/guarantee premiums on any drawn amounts under the covered tranches. These credit GAIL (182.5 Tbtu / yr)
facilities mature on the earlier of December 31, 2020 or the second anniversary of Train 5 completion
date.
(2) Interest on the working capital facility is L+175. Total (104.8 Tbtu / yr)
(3) Interest on the term loan facility is L+225 bps during construction and L+250 bps during operation.
This credit facility matures on the earlier of May 13, 2022 or the second anniversary of project Centrica (91.3 Tbtu / yr)
completion date .
Note: This organizational chart is provided for illustrative purposes only, is not and does not purport to
be a complete organizational chart of Cheniere.
CMI SPA
25Cheniere Cash Flow Build-Up With 7 Trains
($ in billions, except for per share amounts) CQP Corpus Christi
(SPL T1-5/SPLNG/CTPL) (CCL T1-2) Total CEI standalone
CEI cash flow build up (2021 estimated amounts)
Project EBITDA / Deconsolidated for standalone $3.0 $1.3 $4.3 $2.3(1)
Less: Project-level interest expense ($1.0) ($0.5) ($1.5) ($0.5)
Distributable cash flow from project $2.1 $0.8 $2.9 $1.8
% cash flows to CEI (Adjusted for minority interests) 49% 100%
Project cash flows to CEI (Adjusted for minority interests) $1.0 $0.8 $1.8
Total project cash flows to CEI $1.0 $0.8 $1.8
Plus: Management fees to CEI $0.1(1)
Less: CEI G&A ($0.3)(1)
(3)
Less: CEI-level interest expense ($0.0)
CEI cash flow $1.6
CEI cash flow per share $5.8
Current debt outstanding
SPL and CCL project-level debt outstanding(2) $13.1 $8.4 $21.5 –
SPLNG and CTPL project-level debt outstanding $2.5 – $2.5 –
(3)
CEI-level debt outstanding – – – $0.6
Total debt outstanding $15.6 $8.4 $24.0 $0.6
Trains under construction financed with non-recourse project debt – SPL T1-5 (CQP) and CCL T1-2 (CEI)
27.4 MTPA under 20-year SPAs; excess LNG assumed sold at current market prices and shipping rates
For scenario above, estimated tax payments of ~15% of CEI pre-tax cash flow projected to start in
2023/24
Note: See “Forward Looking Statements” slide. Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds.
SPL, SPLNG, CTPL and CCL-level project debt shown above are non-recourse to CEI.
EBITDA, project EBITDA, distributable cash flow, project cash flow, deconsolidated cash flow, pre-tax cash flow and pre-tax cash flow per share are non-GAAP measures. EBITDA is computed as earnings before interest, taxes, depreciation and
amortization. We have not made any forecast of net income, which would be the most comparable financial measure under GAAP, and we are unable to reconcile differences between forecasted non-GAAP measures and net income. Non-
GAAP measures have limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and should be evaluated only on a supplementary basis.
(1) ~$2.3 billion of deconsolidated cash flow to CEI calculated as ~$1.0 billion of CQP distributable cash flow (net of minority interest), plus ~$1.3 billion of CCL Trains 1‐2 EBITDA. CEI standalone EBITDA is estimated to be ~$2.1 billion
calculated as ~$2.3 billion of deconsolidated cash flow to CEI, plus $0.1 billion of management fees, less ~$0.3 billion of CEI G&A.
(2) CCL project-level debt issued at Cheniere Corpus Christi Holdings, LLC (CCH) entity.
(3) Assumes ~277 million CEI shares outstanding for 7-train case – assumes conversion of $1.0 billion PIK Convertible Notes due 2021 and $1.0 billion Senior Secured Convertible Notes due 2025 at $93.64/share.
Source: Bloomberg, DTN ProphetX and Platts
26Conversion - Class B and Subordinated Units
Class B Units:
Mandatory conversion: within 90 days of the substantial completion of Train 3
Optional conversion by a Class B unitholder may occur at any of the following times:
After 83 months from issuance of EPC notice to proceed
Prior to the record date for a quarter in which sufficient cash from operating surplus is generated to distribute $0.425 to
all outstanding common units and the common units to be issued upon conversion
Thirty (30) days prior to the mandatory conversion date
Within a 30-day period prior to a significant event or a dissolution
Subordinated Units:
Subordinated units will convert into common units on a one-for-one basis, provided that there are no
cumulative common unit arrearages, and either of the below distribution hurdles is met:
For three consecutive, non-overlapping four-quarter periods, the distribution paid from “Adjusted Operating Surplus”(1)
to all outstanding units(2) equals or exceeds $0.425 per quarter
For four consecutive quarters, the distribution paid from “Contracted Adjusted Operating Surplus”(1) to all outstanding
units(2) equals or exceeds $0.638 per quarter
(1) As defined in CQP’s partnership agreement.
(2) Includes all outstanding common units (assuming conversion of all Class B units), subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units.
27Sabine Pass Liquefaction Project (SPL)
Current Facility
~1,000 acres in Cameron Parish, LA
40 ft. ship channel 3.7 miles from coast
2 berths; 4 dedicated tugs
5 LNG storage tanks (~17 Bcfe of storage)
5.3 Bcf/d of pipeline interconnection
Liquefaction Trains 1 – 5: Fully Contracted
Lump Sum Turnkey EPC contracts w/ Bechtel
T1 & T2 EPC contract price ~$4.1B
Overall project ~97% complete (as of 12/2015)
Operations estimated 2016
T3 & T4 EPC contract price ~$3.8B
Overall project ~80% complete (as of 12/2015)
Operations estimated 2017
T5 EPC contract price ~$2.9B
Construction commenced June 2015
Liquefaction Train 6
Artist’s rendition FID upon obtaining commercial contracts and
Design production capacity is expected to be ~4.5 mtpa per train, using ConocoPhillips’ Optimized financing
Cascade® Process
Significant infrastructure in place including storage, marine and pipeline interconnection facilities; pipeline quality natural gas
to be sourced from U.S. pipeline network
28SPL Estimated Cash Flows
Trains 1-5 and Trains 1-6
SPL estimated cash flows
($ in billions) SPL Trains 1-5 SPL Trains 1-6
Long term SPAs $2.9 $3.2
CMI SPA payment(1) $0.4 $0.9
(2)
Commodity payments, net $0.3 $0.4
Total SPL revenues $3.6 $4.4
(3)
SPLNG TUA payments ($0.4) ($0.4)
Plant O&M ($0.3) ($0.3)
(4)
Plant maintenance capex ($0.2) ($0.2)
Pipeline costs (primary plant and upstream pipelines) ($0.2) ($0.2)
Total SPL operating expenses ($1.1) ($1.2)
SPL EBITDA $2.6 $3.3
(5)
Less: Project-level interest expense ($0.8) ($0.9)
SPL distributable cash flow to CQP $1.8 $2.3
Note: EBITDA and distributable cash flow are non-GAAP measures. EBITDA is computed as earnings before interest, taxes, depreciation and amortization. We have not made any forecast of net income, which
would be the most directly comparable financial measure under GAAP, and we are unable to reconcile differences between forecasts of these non-GAAP measures and net income. Non-GAAP measures
have limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and should be evaluated only on a supplementary basis.
Assumes future long term contracting of additional 1.5 MTPA at SPL Train 6 (total of 21.25 MTPA of long term SPAs at SPL Trains 1-6) at $3.50 per MMBtu.
(1) CMI SPA payment assumes 100% utilization at $3.00/MMBtu.
(2) Assumes $5.00/MMBtu natural gas price and that off-takers lift 100% of their full contractual entitlement. Amounts are net of estimated natural gas to be used for the liquefaction process.
(3) Includes payments related to reassignment of Total TUA SPLNG capacity and export fees paid to SPLNG.
(4) Majority of costs shown are fixed and covered under multi-year service and supply agreements with equipment and service providers.
(5) Assumes debt at SPL refinanced at 6.00% annual interest rate.
29SPL Construction Schedules Trains 1 – 5
BG DFCD
April/May 2016
GN DFCD
June 2016
KOGAS DFCD
Early Engineering
Jun 2017
April 2017
GAIL DFCD
Mar 2018
Sept 2017
TOTAL & CENTRICA DFCD
Dec 2019
Oct 2019
Stage 1 (Trains 1&2) overall project progress as of Dec 2015 is 97.4% complete vs. Target Plan of 99.2%:
Engineering, Procurement, Subcontracts and Construction are 100%, 100%, 87.1% and 96.2% complete against
Target Plan of 99.9%, 100%, 93.1% and 99.6% respectively
Stage 2 (Trains 3&4) overall project progress as of Dec 2015 is 79.5% complete vs. Target Plan of 85.7%:
Engineering, Procurement, Subcontracts and Construction are 100%, 100%, 51.8% and 55.3% complete against
Target Plan of 99.1%, 100%, 73.0% and 67.2% respectively
Stage 3 (Train 5) overall project progress:
NTP on Train 5 issued to Bechtel on June 30th
Soil stabilization civil works are in progress and the current plan estimates Train 5 operational in 52 months from NTP
Note: Based on Guaranteed Substantial Completion Dates per EPC contract.
30Sabine Pass Liquefaction SPAs
~20 mtpa “take-or-pay” style commercial agreements
~$2.9B annual fixed fee revenue for 20 years
BG Gulf Coast LNG Gas Natural Fenosa Korea Gas Corporation GAIL (India) Limited Total Gas & Power N.A. Centrica plc
Annual Contract
Quantity (MMbtu) 286,500,000 (1) 182,500,000 182,500,000 182,500,000 104,750,000 (1) 91,250,000
Annual Fixed Fees (2) ~$723 MM (3) ~$454 MM ~$548 MM ~$548 MM ~$314 MM ~$274 MM
Fixed Fees $/MMBtu(2) $2.25 - $3.00 $2.49 $3.00 $3.00 $3.00 $3.00
LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH
Term of Contract (4) 20 years 20 years 20 years 20 years 20 years 20 years
BG Energy Gas Natural
Guarantor N/A N/A Total S.A. N/A
Holdings Ltd. SDG S.A
Guarantor/Corporate
A-/A2/A- BBB/Baa2/BBB+ A+/Aa3/AA- NR/Baa2/BBB- AA-/Aa1/AA- A-/Baa1/A-
Credit Rating (5)
Fee During Force
Up to 24 months Up to 24 months N/A N/A N/A N/A
Majeure
Train 1 + additional
Contract Start Train 2 Train 3 Train 4 Train 5 Train 5
volumes with Trains 2,3,4
(1) BG has agreed to purchase 182,500,000 MMBtu, 36,500,000 MMBtu, 34,000,000 MMBtu and 33,500,000 MMBtu of LNG volumes annually upon the commencement of operations of Trains 1, 2, 3 and 4, respectively.
Total has agreed to purchase 91,250,000 MMBtu of LNG volumes annually plus 13,400,000 MMBtu of seasonal LNG volumes upon the commencement of Train 5 operations.
(2) A portion of the fee is subject to inflation, approximately 15% for BG Group, 13.6% for Gas Natural Fenosa, 15% for KOGAS and GAIL (India) Ltd and 11.5% for Total and Centrica.
(3) Following commercial in service date of Train 4. BG will provide annual fixed fees of approximately $520 million during Trains 1-2 operations and an additional $203 million once Trains 3-4 are operational.
(4) SPAs have a 20 year term with the right to extend up to an additional 10 years. Gas Natural Fenosa has an extension right up to an additional 12 years in certain circumstances.
(5) Ratings are provided by S&P/Moody’s/Fitch and subject to change, suspension or withdrawal at anytime and are not a recommendation to buy, hold or sell any security.
31Corpus Christi LNG Terminal
Proposed 5 Train Facility
>1,000 acres owned and/or controlled
Initiated 2 berths, 4 LNG storage tanks
Development (~13.5 Bcfe of storage)
Trains 4-5
Key Project Attributes
45 ft. ship channel 14 miles from coast
Protected berth
Premier Site Conditions
23-mile 48” and 42” parallel pipelines will connect
to several interstate and intrastate pipelines
Liquefaction Trains 1-2: Under Construction
Lump Sum Turnkey EPC contracts w/ Bechtel
Train 3 T1 & T2 EPC contract price ~$7.5B
Under Construction commenced May 2015
Construction Operations estimated 2018
Trains 1-2
Liquefaction Train 3: Partially Contracted
0.8 mtpa contracted to date
Targeting additional 2.1 mtpa
FID upon obtaining commercial contracts and
financing
Liquefaction Trains 4-5: Initiated Development
Artist’s rendition
Permit process started June 2015
Design production capacity is expected to be ~4.5 mtpa per train, using ConocoPhillips’
Optimized Cascade® Process
Commenced Construction on Trains 1-2 in May 2015
32CCL Estimated Cash Flows
Trains 1-2 and Trains 1-3
CCL estimated cash flows
($ in billions) CCL Trains 1-2 CCL Trains 1-3
Long term SPAs $1.4 $1.9
(1)
CMI SPA payment $0.2 $0.5
(2)
Commodity payments, net $0.1 $0.1
Total CCL revenues $1.7 $2.5
Plant O&M ($0.2) ($0.2)
(3)
Plant maintenance capex ($0.1) ($0.1)
Pipeline costs (primary plant and upstream pipelines) ($0.1) ($0.2)
Total CCL operating expenses ($0.4) ($0.5)
CCL EBITDA $1.3 $2.0
(4)
Less: Project-level interest expense ($0.5) ($0.7)
CCL distributable cash flow to CEI $0.8 $1.3
Note: EBITDA and distributable cash flow are non-GAAP measures. EBITDA is computed as earnings before interest, taxes, depreciation and amortization. We have not made any forecast of net
income, which would be the most directly comparable financial measure under GAAP, and we are unable to reconcile differences between
forecasts of these non-GAAP measures and net income. Non-GAAP measures have limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported
under GAAP, and should be evaluated only on a supplementary basis.
Assumes future long term contracting of additional ~2.1 MTPA at CCL Train 3 (total of 10.5 MTPA of long term SPAs at CCL Trains 1-3) at $3.50 per MMBtu.
(1) CMI SPA payment assumes 100% utilization at $3.00/MMBtu.
(2) Assumes $5.00/MMBtu natural gas price and that off-takers lift 100% of their full contractual entitlement. Amounts are net of estimated natural gas to be used for the liquefaction process.
(3) Majority of costs shown related to service-based payments to be contracted over a multi-year term.
(4) Assumes debt at CCL refinanced at 6.00% annual interest rate.
33Corpus Christi Liquefaction Project Schedule
Train 1 DFCD
Oct 2019
Feb 2019
Train 2 DFCD
July 2020
June 2019
Stage 1 (Trains 1&2) overall project progress as of December 2015:
Engineering, Procurement, and Construction has progressed to 93.6%, 41.9%, and 2.2% compared to a plan of
87.3%, 24.9%, and 3.7% respectively.
NTP issued, construction commenced for Trains 1-2 in May 2015
Note: Based on Guaranteed Substantial Completion Dates per EPC contract.
34Corpus Christi Liquefaction SPAs
SPA progress: ~8.42 mtpa “take-or-pay” style commercial agreements
~$1.5B annual fixed fee revenue for 20 years
PT Pertamina Woodside Energy Électricité de EDP Energias de
(Persero) Endesa S.A. Iberdrola S.A. Gas Natural Fenosa Trading France Portugal S.A.
Annual Contract
Quantity (TBtu) 79.36 117.32 39.68 78.20 44.12 40.00 40.00
Annual Fixed Fees (1) ~$278 MM ~$411 MM ~$139 MM ~$274 MM ~$154 MM ~$140 MM ~$140 MM
Fixed Fees $/MMBtu (1) $3.50 $3.50 $3.50 $3.50 $3.50 $3.50 $3.50
LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH
Term of Contract (2) 20 years 20 years 20 years 20 years 20 years 20 years 20 years
Gas Natural Woodside
Guarantor N/A N/A N/A N/A N/A
SDG, S.A. Petroleum, LTD
Guarantor/Corporate
BB+/Baa3/BBB- BBB/Baa2/BBB+ BBB/Baa1/BBB+ BBB/Baa2/BBB+ BBB+/Baa1/BBB+ A+/A1/A BB+/Baa3/BBB-
Credit Rating (3)
Contract Start Train 1 / Train2 Train 1 Train 1 / Train 2 Train 2 Train 2 Train 2 Train 3
(1) 12.75% of the fee is subject to inflation for Pertamina; 11.5% for Woodside; 14% for all others
(2) SPA has a 20 year term with the right to extend up to an additional 10 years.
(3) Ratings are provided by S&P/Moody’s/Fitch and subject to change, suspension or withdrawal at anytime and are not a recommendation to buy, hold or sell any security.
35FERC Applications for Liquefaction Projects
FERC FERC FERC Scheduled DOE
Quantity EIS / Under
LNG Export Projects Pre-filing Application Scheduling Date for EIS FERC Approval Non FTA
Bcf/d EA Construction
Date Date Notice Issued or EA Final
Sabine Pass Liquefaction T1-4 2.8 7/26/10 1/31/11 12/16/11 EA 4/16/12 8/7/12
Cameron LNG T1-3 1.7 4/30/12 12/10/12 11/21/13 EIS 4/30/14 6/19/14 9/10/14
1.4
Freeport LNG
0.4
12/23/10 8/31/12 1/6/14 EIS 6/16/14 7/30/14 11/14/14
Dominion Cove Point LNG 1.0 6/1/12 4/1/13 3/12/14 EA 5/15/14 9/29/14 5/7/15
Corpus Christi Liquefaction T1-3 2.1 12/13/11 8/31/12 2/12/14 EIS 10/8/14 12/30/14 5/12/15 T1-2:
Sabine Pass Liquefaction T5-6 1.38 2/27/13 9/30/13 11/03/14 EA 12/12/14 4/6/15 6/26/15 T5:
Jordan Cove Energy 1.2/0.8 2/29/12 5/22/13 7/16/14 EIS 9/30/15
Oregon LNG 1.25 7/3/12 6/7/13 4/17/15 EIS 2/12/16
Lake Charles LNG 2.0 3/30/12 3/25/14 1/26/15 EIS 8/14/15 12/17/15
Magnolia 1.08 3/20/13 4/30/14 4/30/15 EIS 11/16/15
Southern LNG 0.5 12/5/12 3/10/14 EA
Golden Pass 2.6 5/16/13 7/7/14 6/26/15 EA 3/4/16
Gulf LNG 1.3 12/6/12 6/19/15 EIS
Cameron LNG Expansion T4-5 1.4 2/24/15 9/28/15 EIS
6 projects have received FERC approval and final DOE approval for Non FTA
Source: Office of Fossil Energy, U.S. Department of Energy; U.S. Federal Energy Regulatory Commission; Company releases
Note: National Environmental Policy Act (NEPA) empowers FERC as the lead Federal agency to prepare an Environmental Impact Statement in cooperation with other state and federal agencies
36U.S. LNG Export Projects
Quantity
Company DOE FERC Contracts
(Bcf/d)
Cheniere Sabine Fully
2.2 Fully permitted
Pass T1 – T4 Subscribed
Oregon LNG Fully
Freeport 1.8 Fully permitted Subscribed
Fully
Lake Charles 2.0 FTA Subscribed
Jordan Cove Dominion Cove Point Dominion Cove Fully
1.0 Fully permitted
Point Subscribed
Fully
Cameron LNG T1-3 1.7 Fully permitted Subscribed
Lake Charles
Southern LNG
Golden Pass Jordan Cove 1.2/0.8 FTA
Gulf LNG
Freeport LNG
Oregon LNG 1.25 FTA
Magnolia
Corpus Christi Cameron LNG Cheniere Corpus Partially
2.1 Fully permitted
Christi T1 – T3 Subscribed
Sabine Pass
Cheniere Sabine T5
1.3 Fully permitted
Pass T5 – T6 Subscribed
Fully
Southern LNG 0.5 FTA Subscribed
Partially
Magnolia LNG 0.5 FTA Subscribed
Under Construction
Filed FERC Application Fully
Golden Pass LNG 2.0 FTA Subscribed
Gulf LNG 1.3 FTA
Cameron LNG T4-5 1.4 FTA
Plus other proposed LNG export projects that have not filed a FERC application.
Source: Office of Oil and Gas Global Security and Supply, Office of Fossil Energy, U.S. Department of Energy; Excelerate has requested that FERC put on hold the review its application.
U.S. Federal Energy Regulatory Commission; Company releases
Application filing = v FERC scheduling notice issued =
37CHENIERE ENERGY, INC. INVESTOR RELATIONS CONTACTS Randy Bhatia Director, Finance and Investor Relations – (713) 375-5479, randy.bhatia@cheniere.com Katy Cox Senior Analyst, Investor Relations – (713) 375-5079, katy.cox@cheniere.com
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